Sw-sagd with between heel and toe injection

ABSTRACT

The present disclosure relates to a particularly effective well configuration that can be used for single well steam assisted gravity drainage (SW-SAGD), wherein steam injection occurs at one or more points between the heel and toe, instead of at the toe as in the prior art.

PRIORITY CLAIM

This application is a non-provisional application which claims benefitunder 35 USC §119(e) to U.S. Provisional Application Ser. No. 62/153,269filed Apr. 27, 2015, entitled “SW-SAGD WITH BETWEEN HEEL AND TOEINJECTION,” which is incorporated herein in its entirety.

FEDERALLY SPONSORED RESEARCH STATEMENT

Not Applicable.

REFERENCE TO MICROFICHE APPENDIX

Not applicable.

FIELD OF THE DISCLOSURE

This disclosure relates generally to methods that can advantageouslyproduce oil using steam-based mobilizing techniques. In particular, itrelates to improved single well gravity drainage techniques with bettersteam chamber development than previously available.

BACKGROUND OF THE DISCLOSURE

Oil sands are a type of unconventional petroleum deposit, containingnaturally occurring mixtures of sand, clay, water, and a dense andextremely viscous form of petroleum technically referred to as“bitumen,” but which may also be called heavy oil or tar. Bitumen is soheavy and viscous (thick) that it will not flow unless heated or dilutedwith lighter hydrocarbons. At room temperature, bitumen is much likecold molasses, and the viscosity can be in excess of 1,000,000 cP.

Due to their high viscosity, these heavy oils are hard to mobilize, andthey generally must be heated in order to produce and transport them.One common way to heat bitumen is by injecting steam into the reservoir.Steam Assisted Gravity Drainage or “SAGD” is the most extensively usedtechnique for in situ recovery of bitumen resources in the McMurrayFormation in the Alberta Oil Sands.

In a typical SAGD process, two horizontal wells are stacked one over theother and vertically spaced by 4 to 10 meters (m). See FIG. 1. Theproduction well is located near the bottom of the pay and the steaminjection well is located directly above and parallel to the productionwell. Steam is injected continuously into the injection well, where itrises in the reservoir and forms a steam chamber. With continuous steaminjection, the steam chamber will continue to grow upward and laterallyinto the surrounding formation. At the interface between the steamchamber and cold oil, steam condenses and heat is transferred to thesurrounding oil. This heated oil becomes mobile and drains, togetherwith the condensed water from the steam, into the production well due togravity segregation within steam chamber.

The use of gravity gives SAGD an advantage over conventional steaminjection methods. SAGD employs gravity as the driving force and theheated oil remains warm and movable when flowing toward the productionwell. In contrast, conventional steam injection displaces oil to a coldarea, where its viscosity increases and the oil mobility is againreduced.

Although quite successful, SAGD does require large amounts of water inorder to generate a barrel of oil. Some estimates provide that 1 barrelof oil from the Athabasca oil sands requires on average 2 to 3 barrelsof water, and it can be much higher, although with recycling the totalamount can be reduced. In addition to using a precious resource,additional costs are added to convert those barrels of water to highquality steam for down-hole injection. Therefore, any technology thatcan reduce water or steam consumption has the potential to havesignificant positive environmental and cost impacts.

Additionally, SAGD is less useful in thin stacked pay-zones, becausethin layers of impermeable rock in the reservoir can block the expansionof the steam chamber leaving only thin zones accessible, thus leavingthe oil in other layers behind. Further, the wells need a verticalseparation of about 4-5 meters in order to maintain the steam trap. Inwells that are closer, live steam can break through to the producerwell, resulting in enlarged slots that permit significant sand entry,well shutdown and damage to equipment.

Indeed, in a paper by Shin & Polikar (2005), the authors simulatedreservoir conditions to determine which reservoirs could be economicallyexploited. The simulation results showed that for Cold Lake-typereservoirs, a net pay thickness of at least 20 meters was required foran economic SAGD implementation. A net pay thickness of 15 m was stilleconomic for the shallow Athabasca-type reservoirs because of the highpermeability of this type of reservoir, despite the very high bitumenviscosity at reservoir conditions. In Peace River-type reservoirs, netpay thicker than 30 meters was expected to be required for a successfulSAGD performance due to the low permeability of this type of reservoir.The results of the study indicate that the shallow Athabasca-typereservoir, which is thick with high permeability (high k×h), is a goodcandidate for SAGD application, whereas Cold Lake and Peace River-typereservoirs, which are thin with low permeability, are not as goodcandidates for conventional SAGD implementation.

In order to address the thin payzone issue, some petroleum engineershave proposed a single wellbore steam assisted gravity drainage or“SW-SAGD.” See e.g., FIG. 2A. In SW-SAGD, a horizontal well is completedand assumes the role of both injector and producer. In a typical case,steam is injected at the toe of the well, while hot reservoir fluids areproduced at the heel of the well, and a thermal packer is used toisolate steam injection from fluid production (FIG. 2A).

Another version of SW-SAGD uses no packers, simply tubing to segregateflow. Steam is injected at the end of the horizontal well (toe) throughan isolated concentric coiled tubing (ICCT) with numerous orifices. InFIG. 2B a portion of the injected steam and the condensed hot waterreturns through the annulus to the well's vertical section (heel). Theremaining steam, grows vertically, forming a chamber that expands towardthe heel, heating the oil, lowering its viscosity and draining it downthe well's annular by gravity, where it is pumped up to the surfacethrough a second tubing string.

Advantages of SW-SAGD might include cost savings in drilling andcompletion and utility in relatively thin reservoirs where it is notpossible to drill two vertically spaced horizontal wells. Basicallysince there is only one well, instead of a well pair, start up costs areonly half that of conventional SAGD. However, the process is technicallychallenging and the method seems to require even more steam thanconventional SAGD.

Field tests of SW-SAGD are not extensively documented in the literature,but the available evidence suggests that there is considerable room tooptimize the SW-SAGD process.

For example, Falk overviewed the completion strategy and some typicalresults for a project in the Cactus Lake Field, Alberta Canada. Aroughly 850 m long well was installed in a region with 12 to 16 m of netpay to produce 12° API gravity oil. The reservoir contained clean,unconsolidated, sand with 3400 and permeability. Apparently, no attemptswere made to preheat the reservoir before initiation of SW-SAGD. Steamwas injected at the toe of the well and oil produced at the heel. Oilproduction response to steam was slow, but gradually increased to morethan 100 m³/d. The cumulative steam-oil ratio was between 1 and 1.5 forthe roughly 6 months of reported data.

McCormack also described operating experience with nineteen SW-SAGDinstallations. Performance for approximately two years of production wasmixed. Of their seven pilot projects, five were either suspended orconverted to other production techniques because of poor production.Positive results were seen in fields with relatively high reservoirpressure, relatively low oil viscosity, significant primary productionby heavy-oil solution gas drive, and/or insignificant bottom-waterdrive. Poor results were seen in fields with high initial oil viscosity,strong bottom-water drive, and/or sand production problems. Although theauthors noted that the production mechanism was not clearly understood,they suspected that the mechanism was a mixture of gravity drainage,increased primary recovery because of near-wellbore heating viaconduction, and hot water induced drive/drainage.

Moriera (2007) simulated SW-SAGD using CMG-STARS, attempting to improvethe method by adding a pre-heating phase to accelerate the entrance ofsteam into the formation, before beginning a traditional SW-SAGDprocess. Two processes were modeled, as well as conventional SW-SAGD anddual well SAGD. The improved processes tested were 1) Cyclicinjection-soaking-production repeated three times (20, 10 and 30 daysfor injection, soaking and production respectively), and 2) Cyclicinjection repeated three times as in 1), but with the well divided intotwo portions by a packer, where preheat steam was injected at the toeand center and circulated throughout the well, but production occurringonly in the producing heel half with toe steam injection.

They found that the cyclical preheat period provided better heatdistribution in the reservoir and reduces the required injectionpressure, although, it increased the waiting time for the continuousinjection process. Additionally, the division of the well by a packerand the injection of the steam in two points, in the middle and at theextremity of the well, helped the distribution of the heat in theformation and favor oil recovery in the cyclical injection phase. Theyalso found that in the continuous injection phase, the division of thewell induces an increase of the volume of the steam chamber, andimproved the oil recovery in relation to the SW-SAGD process. Also, anincrease of the blind interval (blank pipe), between the injection andproduction passages, increased the difference of the pressure and drivesthe displaced oil in the injection section into the production area, butcaused imprisonment of the oil in the injection section, reducing therecovery factor.

Overall, the authors concluded that modifications in SW-SAGD operationstrategies can lead to better recovery factors and oil steam ratios thanthose obtained with the DW-SAGD process, but that SW-SAGD performancewas highly variable.

It is noted that these authors did use central (and toe) injectionduring the preheat or startup phase. However, the steam was allowed totravel the length of the well, thus the entire well was preheated.Further, actual production phase was the same as usual, with toeinjection and heel production. Since the steam is injected at the toesegment, it is expected that the oil from the steam end, at least partof it, will not be recoverable.

Although beneficial, the SW-SAGD methodology could be further developedto further improve its cost effectiveness. This application addressessome of those needed improvements.

SUMMARY OF THE DISCLOSURE

The conventional SW-SAGD utilizing one single horizontal well to injectsteam into reservoir through toe and produce liquid (oil and water)through mid and heel of the well has potential for thin-zoneapplications where placing two horizontal wells with 5 m verticallyapart required in the SAGD is technically and economically challenging.SW-SAGD, however, exhibits several disadvantages leading to slow steamchamber growth and low oil rate.

First of all, SW-SAGD is not efficient in developing the steam chamber.Due to the arrangement of injection and production points in theconventional SW-SAGD, the steam chamber can grow only in one sidetowards the heel. In other words, only one half of the surface areasurrounding the steam chamber is available for heating and draining oil.

Secondly, a large portion of the horizontal well length perforated forproduction does not actually contribute to oil production until thesteam chamber expands over the whole length. This is particularly trueduring the early stage where only a small portion of the well close tothe toe collects oil.

This disclosure proposes instead to use variations of steam injectionpoint location and number to improve the recovery performance. Theessential idea of the invention is to allow full development of steamchamber from both sides and increase the effective production welllength.

FIG. 1B shows schematically a simple, but effective (as demonstratedlater by simulation) process modified from the conventional SW-SAGD, inwhich the steam injection point is placed in the middle of thehorizontal well. The toe and heel sections of the horizontal well,isolated from the steam injection portion by thermal packers within thewellbore, are perforated and serve as producer wells to collect oil andcondensed water.

As illustrated in FIG. 3, the steam chamber can now grow from bothsides, with the effective thermal and drainage interfaces virtuallydoubled. Consequently, the effective production well length is doubled,resulting in a significant uplift in oil production rate. To furtherimprove the performance SW-SAGD, multiple steam injection points can beintroduced into the wellbore to initiate and grow a serial of steamchambers simultaneously.

FIG. 4 gives an example with two injection points, one at ¼ well lengthfrom the heel and the other ¾ well length from the heel. The SW-SAGDwith multiple steam injection points can significantly accelerate theoil recovery by engaging more well length into effective production. Thenumber of the steam injection points and intervals between them normallyneed to be determined and optimized based on the reservoir propertiesand economics.

It is worth pointing out that implementing center or multi-injectionpoints within a single wellbore adds complexity to the wellbore design,and consequently well cost (as compared to standard SW-SAGD). Forexample, the well completion will require packers on either side of thesteam injection points, and the ICCT will require outlets for steam ifmulti-point injection methods are used. Nevertheless, the proposedinvention presents a big potential, and the increased cost isincremental as compared with the cost of saving in injector welldrilling. Further, as shown in FIGS. 7 and 8, the increased recoveryherein is a likely game-changer for SW-SAGD applications, especially asapplied to thin-zone bitumen reservoirs.

The method is otherwise similar to SAGD, which requires steam injection(often in both wells) to establish fluid communication between wells(not needed here) as well as a steam chamber. When the steam chamber iswell developed, injection proceeds in only the injectors, and productionbegins at the producer. Alternatively, the startup or preheat period canbe reduced or even eliminated.

Preferably, the method includes preheat cyclic steam phases, whereinsteam is injected throughout both injector and producer segment, fore.g. 20-50 days, then allowed to soak into the reservoir, e.g., for10-30 days, and this preheat phase is repeated two or preferably threetimes. This ensures adequate steam chamber growth along the length ofthe well.

Also preferred the steam injection can be combined with solventinjection or non-condensable gas injection, such as CO₂, as solventdilution and gas lift can assist in recovery.

The invention can comprise any one or more of the following embodiments,in any combination(s) thereof:

An improved method of producing heavy oils from a SW-SAGD, wherein steamin injected into a toe end of a horizontal well to mobilize oil which isthen produced at a heel end of said horizontal well, the improvementcomprising providing one or more injection points for steam between saidheel end and said toe end, thus improving a CSOR of said horizontal wellat a time period as compared to a similar well with steam injection onlyat said toe end.

A method of producing heavy oils from a reservoir by single well steamand gravity drainage (SW-SAGD), comprising: providing a horizontal wellbelow a surface of a reservoir; said horizontal well having a toe endand a heel end and a middle therebetween; injecting steam into one ormore injection points between said toe end and said heel end; andsimultaneously (with said steam injection) producing mobilized heavyoil; wherein said method produces more oil at a time point than asimilar SW-SAGD well with steam injection only at said toe.

A well configuration for producing heavy oils from a reservoir by singlewell steam and gravity drainage (SW-SAGD), comprising: a horizontal wellin a subsurface reservoir; said horizontal well having a toe end and aheel end and having at least three segments comprising: at least twoproduction segments bracketing at least one injection segment; saidproduction segments fitted for production; and said injection segmentsfitted for injection.

A method or configuration as herein described, wherein each injectionpoint is separated from a production segment by at least two thermalpackers.

A method or configuration as herein described, wherein an injectionpoint is at said middle.

A method or configuration as herein described, wherein two injectionpoints are at about ¼ and ¾ of a horizontal length of said well.

A method or configuration as herein described, said at least twoinjection segments fitted with tubing having two orifices to injectsteam into said two injection segments.

A method as herein described, wherein production and injection takeplace simultaneously.

A method as herein described wherein injected steam includes solvent.

A method as herein described wherein said method includes a preheatingphase wherein steam is injected along the entire length of the well.

A method or configuration as herein described wherein said methodincludes a cyclic preheating phase comprising a steam injection periodalong the entire length of the well followed by a soaking period.

A method as herein described wherein said method includes a pre-heatingphase comprising a steam injection in both the injection segment and theproduction segment followed by a soaking period.

Preferably, two or three cyclic preheating phases are used. Preferablythe soaking period is 10-30 days or about 20 days.

“SW-SAGD” as used herein means that a single well serves both injectionand production purposes, but nonetheless there may be an array ofSW-SAGD wells to effectively cover a given reservoir. This is incontrast to conventional SAGD where the injection and production wellsare separate during production phase, necessitating a wellpair at eachlocation.

As used herein, “preheat” or “startup” is used in a manner consistentwith the art. In SAGD the preheat stage usually means steam injectionthroughout both wells until the steam chamber is well developed and thetwo wells are in fluid communication. Thus, both wells are fitted forsteam injection. Later during production, the production well is fittedfor production, and steam injected into the injector well only. InSW-SAGD, the meaning is the same, except that there is only a singlewell. Thus, preheat means steam injection throughout the well (e.g., nopackers) in order to develop a steam chamber along the entire length ofthe well.

As used herein, “cyclic preheat” is used in a manner consistent with theart, wherein the steam is injected, preferably throughout the horizontallength well, and left to soak for a period of time, and any oilcollected. Typically the process is then repeated two or more times.Steam injection throughout the length of the well can be achieved hereinby merely removing or opening packers, such that steam travels thelength of the well, exiting any slots or perforations used forproduction.

As used wherein, a “production phase” is that phase where steaminjection and production occur simultaneously, and is understood in theart to be different from a “preheat” or “startup” phase, where steam isinjected for preheat purposes and the well configuration is different.The invention herein relates to steam injection during production phasethat occurs at one or more locations between the heel and toe. Sincethere is only a single well, packers are typically required to separatethe steam injection and production segments so that they can occursimultaneously.

After preheat or cyclic preheat, the well is used for production, andsteam injection occurs only at the points designated hereunder, withpackers and preferably with blank pipe separating injection section(s)from production sections. The blank pipe, with relatively short lengthor preferably controllable length during operation, may help providedifferential pressure and thus minimize steam breakthrough at theproduction section. Injection sections need not be large herein, and canbe on the order of <1-100 m, or 1-50 m or 20-40.

The ideal length of blank pipe will vary according to reservoircharacteristics, oil viscosity as well as injection pressures andtemperatures, but a suitable length is in the order of 10-40 feet or20-30 feet of blank liner. It may also be possible to use a slidingsleeve and thus allow the benefits of a blind interval, yet recover theoil behind the blind interval by sliding the sleeve in one direction orthe other, thus sliding the blind interval. It may also be possible tosubstitute FCDs for the blind pipe.

A suitable arrangement might thus be a 300-500 meter long productionpassage, 10-40 meter blind interval, packer, <1-40 meter long injectionpassage followed by another packer, 10-40 meter blind interval and300-500 meter production passage. Another arrangement might have twoinjection points: 300 meter production, 10-20 blind interval, packer,1-10 injection, packer, 10-20 blind interval, 600 meter production,10-20 blind interval, packer, 1-10 m injection, packer, 10-20 blindinterval, 300 meter production. Yet another arrangement might be 200meter production, 10-20 blind interval, packer, 1-10 injection, packer,10-20 blind interval, 400 meter production, 10-20 blind interval,packer, 1-10 m injection, packer, 10-20 blind interval, 400 meterproduction, 10-20 blind interval, packer, 1-10 injection, packer, 10-20blind interval, and 200 meter production.

By “heel end” herein we include the first joint in the horizontalsection of the well, or the first two joints.

By “toe end” herein we include the last joint in the horizontal sectionof the well, or the last two joints.

By “middle” herein we refer to 25-75% of the horizontal well length, butpreferably from 40-60% or 45-55%.

By “between the toe end and the heel end”, we mean an injection pointthat lies between the first and last joint or two of the ends of thehorizontal portion of the well.

As used herein, flow control device “FCD” refers to all variants oftools intended to passively control flow into or out of wellbores bychoking flow (e.g., creating a pressure drop). The FCD includes bothinflow control devices “ICDs” when used in producers and outflow controldevices “OCDs” when used in injectors. The restriction can be in form ofchannels or nozzles/orifices or combinations thereof, but in any casethe ability of an FCD to equalize the inflow along the well length isdue to the difference in the physical laws governing fluid flow in thereservoir and through the FCD. By restraining, or normalizing, flowthrough high-rate sections, FCDs create higher drawdown pressures andthus higher flow rates along the bore-hole sections that are moreresistant to flow. This corrects uneven flow caused by the heel-toeeffect and heterogeneous permeability.

By “providing” a well, we mean to drill a well or use an existing well.The term does not necessarily imply contemporaneous drilling because anexisting well can be retrofitted for use, or used as is.

By being “fitted” for injection or production what we mean is that thecompletion has everything is needs in terms of equipment needed forinjection or production.

“Vertical” drilling is the traditional type of drilling in oil and gasdrilling industry, and includes any well<45° of vertical.

“Horizontal” drilling is the same as vertical drilling until the“kickoff point” which is located just above the target oil or gasreservoir (pay-zone), from that point deviating the drilling directionfrom the vertical to horizontal. By “horizontal” what is included is anangle within 45° (≦45°) of horizontal. Of course every horizontal wellhas a vertical portion to reach the surface, but this is conventional,understood, and typically not discussed.

A “perforated liner” or “perforated pipe” is a pipe having a pluralityof entry-exits holes throughout for the exit of steam and entry ofhydrocarbon. The perforations may be round or long and narrow, as in a“slotted liner,” or any other shape.

A “blank pipe” or “blank liner” is a joint that lacks any holes.

A “packer” refers to a downhole device used in almost every completionto isolate the annulus from the production conduit, enabling controlledproduction, injection or treatment. A typical packer assemblyincorporates a means of securing the packer against the casing or linerwall, such as a slip arrangement, and a means of creating a reliablehydraulic seal to isolate the annulus, typically by means of anexpandable elastomeric element. Packers are classified by application,setting method and possible retrievability.

A “joint” is a single section of pipe.

The use of the word “a” or “an” when used in conjunction with the term“comprising” in the claims or the specification means one or more thanone, unless the context dictates otherwise.

The term “about” means the stated value plus or minus the margin oferror of measurement or plus or minus 10% if no method of measurement isindicated.

The use of the term “or” in the claims is used to mean “and/or” unlessexplicitly indicated to refer to alternatives only or if thealternatives are mutually exclusive.

The terms “comprise”, “have”, “include” and “contain” (and theirvariants) are open-ended linking verbs and allow the addition of otherelements when used in a claim.

The phrase “consisting of” is closed, and excludes all additionalelements.

The phrase “consisting essentially of” excludes additional materialelements, but allows the inclusions of non-material elements that do notsubstantially change the nature of the invention.

The following abbreviations are used herein:

bbl Oil barrel, bbls is plural CPSW-SAGD Center point injection SW-SAGDCSOR Cumulative Steam to oil ratio CSS Cyclic steam stimulation DW-SAGDdual well SAGD ES-SAGD Expanding solvent-SAGD FCD Flow control deviceMPSW-SAGD MULTI-Point SW-SAGD OOIP Original Oil in Place SAGD Steamassisted gravity Drainage SD Steam drive SOR Steam to oil ratio SW-SAGDSingle well SAGD

BRIEF DESCRIPTION OF THE DRAWINGS

FIG. 1A shows traditional SAGD wellpair, with an injector well a fewmeters above a producer well.

FIG. 1B shows a typical steam chamber.

FIG. 2A shows a SW-SAGD well, wherein the same well functions for bothsteam injection and oil production. Steam is injected into the toe (inthis case the toe is updip of the heel), and the steam chamber growstowards the heel. Steam control is via packer.

FIG. 2B shows another SW-SAGD well configuration wherein steam isinjected via ICCT, and a second tubing is provided for hydrocarbonremoval.

FIG. 3 center point injection SW-SAGD (CPSW-SAGD).

FIG. 4 multi-point injection SW-SAGD (MPSW-SAGD). One injection point issituated at ¼ well length from the heel and the other ¾ well length fromthe heel, and each steam chamber grows in both directions, meeting inthe middle of the well.

FIG. 5 shows simulated oil saturation profiles of (A) conventionalSW-SAGD, (B) SW-SAGD with center injection point (half of full welllength shown), and (C) SW-SAGD with two injection points (quarter offull well length shown) after 3 years of steam injection. Allsimulations performed with CMG-STARS using a fine grid block.

FIG. 6 shows simulated temperature profiles of (A) conventional SW-SAGD,(B) CPSW-SAGD with center injection point (half of full well lengthshown), and (C) MPSW-SAGD with two injection points (quarter of fullwell length shown) after 3 years of steam injection.

FIG. 7 shows a comparison of oil production rate. Note that theEnd-Injector case is conventional SW-SAGD, the Center-Injector case isCWSW-SAGD with a center injection point, and the Two-Injector case isMPSW-SAGD with two injection points spaced for equally sized steamchambers.

FIG. 8 is a comparison of oil recovery using the same three wellconfigurations as in FIG. 7.

DESCRIPTION OF EMBODIMENTS

The present disclosure provides a novel well configurations and methodfor SW-SAGD.

This novel modification to the conventional single-well SAGD (SW-SAGD)process varies the location and number of steam injection points duringthe production phase, and the same points can be used in preheat orcyclic preheat.

The conventional SW-SAGD process grows a steam chamber and drains oil bygravity by utilizing one single horizontal well with steam injected onlyat the toe and liquid produced through the rest of the well. SW-SAGD haspotential to unlock vast thin-zone (5-20 m pay) oil sand resources whereSAGD using well pairs is economically and technically challenging.

However, the conventional SW-SAGD normally suffers from slow steamchamber growth and low oil production rate as the steam chamber can onlygrow from toe gradually towards the heel. This appears to be veryineffective, and seriously limits the usefulness of SW-SAGD.

In this invention, we propose an improved SW-SAGD process with one ormore steam injection points between the toe and heel end. For example, acenter steam injection point can be used, or multiple steam injectionpoints spaced for equal steam chamber development can be used tosignificantly accelerate steam chamber growth and oil recovery. Thesuperior recovery performance of the proposed configuration and methodsis confirmed by our simulation results.

It is surprising that this elegant solution to the low production levelissue with SW-SAGD has never been proposed before. However, one reasonis that most SAGD simulations are either run as 2D cross-sections, or as3D models with relatively large gridding in the wellbore direction(typically 25-100 m), both of which will either eliminate the “endeffect” (in the case of 2D simulations), or seriously under-estimate it(in the case of large-block 3D simulations). Thus, given the toolstypically available to the petroleum engineer, even if the idea wasattempted, traditional models would not show any benefit.

Conventional SW-SAGD

The conventional SW-SAGD utilizes one single horizontal well to injectsteam into reservoir through toe and produce liquid (oil and water)through mid and heel of the well, as schematically shown in FIGS. 2A andB. A steam chamber is expected to form and grow from the toe of thewell. Similar to the SAGD process, the oil outside of the steam chamberis heated up with the latent heat of steam, becomes mobile, and drainswith steam condensate under gravity towards the production portion ofthe well. With continuous steam injection through toe and liquidproduction through the rest of the well, the steam chamber expandsgradually towards to the heel to extract oil.

Due to the unique arrangement of injection and production, the SW-SAGDcan also benefit from pressure drive in addition to gravity drainage asthe recovery mechanisms. Also, compared with its counterpart, thetraditional dual well or “DW-SAGD” configuration, SW-SAGD requires onlyone well, thereby saving almost half of well cost. SW-SAGD becomesparticularly attractive for thin-zone applications where placing twohorizontal wells with the typical 4-10 m vertical separation required inthe SAGD is technically and economically challenging.

SW-SAGD, however, exhibits several disadvantages leading to slow steamchamber growth and low oil rate. First of all, SW-SAGD is not efficientin developing the steam chamber. The steam chamber growth dependslargely upon the thermal conduction to transfer steam latent heat intocold reservoir and oil drainage under gravity along the chamberinterface. Due to the arrangement of injection and production points inthe conventional SW-SAGD, the steam chamber can grow only directiontowards the heel. In other words, only one half of the surface areasurrounding the steam chamber is available for heating and draining oil.Secondly, a large portion of the horizontal well length perforated forproduction does not actually contribute to oil production until thesteam chamber expands over the whole length. This is particularly trueduring the early stage where only a small portion of the well close tothe toe collects oil.

CPSW-SAGD

To overcome the aforementioned issues associated with the conventionalSW-SAGD, we propose steam injection in between the heel and toe toimprove the recovery performance at about the center of the well. By“center” herein, we refer to roughly the center of the longitudinalportion of the well, and do not consider the vertical portion. By doingthis, the steam chamber can grow in both directions from roughly themiddle. The essential idea is to allow full development of steam chamberfrom both sides and increase the effective production well lengthearlier in the process.

FIG. 3 shows schematically a simple, but effective (as demonstratedlater by simulation) process modified from the conventional SW-SAGD, inwhich the steam injection point is placed in the middle of thehorizontal well. The toe and heel sections of the horizontal well,isolated from the steam injection portion by thermal packers (indicatedby the boxes with the X therein) within the wellbore, are perforated andserve as producer to collect heated oil and condensed water.

As illustrated in FIG. 3, the steam chamber can now grow from bothsides, with the effective thermal and drainage interfaces virtuallydoubled. Consequently, the effective production well length is doubled,resulting in a significant uplift in oil production rate.

MPSW-SAGD

To further improve the performance SW-SAGD, multiple steam injectionpoints can be introduced into the wellbore to initiate and grow a serialof steam chambers simultaneously. FIG. 4 gives an example with twoinjection points, one at ¼ well length from the heel and the other ¾well length from the heel. The SW-SAGD with multiple steam injectionpoints can significantly accelerate the oil recovery by engaging morewell length into effective production. With two injection points asplaced in FIG. 4, the dual steam chambers will each grow in bothdirections, and meet in roughly the middle of the well.

The number of the steam injection points and intervals between themnormally need to be determined and optimized based on the reservoirproperties and economics. It is worth pointing out that implementingmultiple steam injection points within a single wellbore adds complexityto the wellbore design and consequently well cost, necessitating theproviding of multiple injections points and additional packers.Nevertheless, the proposed invention presents a considerable potentialfor improving SW-SAGD applications to thin-zone bitumen reservoirs.

Steam Chamber Simulations

To evaluate the performance of the proposed modification to theconventional SW-SAGD, numerical simulation with a 3D homogeneous modelwas conducted using Computer Modeling Group® Thermal & AdvancedProcesses Reservoir Simulator, abbreviated CMG-STARS. CMG-STARS is theindustry standard in thermal and advanced processes reservoirsimulation. It is a thermal, k-value (KV) compositional, chemicalreaction and geomechanics reservoir simulator ideally suited foradvanced modeling of recovery processes involving the injection ofsteam, solvents, air and chemicals.

The reservoir simulation model was provided the average reservoirproperties of Athabasca oil sand, with an 800 m long horizontal wellplaced at the bottom of a 20 m pay. The simulation considered threecases, the conventional SW-SAGD, CPSW-SAGD with centered injector, andMPSW-SAGD with two injectors (one 200 m and the other 600 m from heel).A smaller than usual grid size was modeled in order to capture theeffects (e.g., 1-5 m, preferably 2 m). No startup period was modeled.The modeled operational conditions, including pressure and injectionrates, were similar to a typical SAGD operation.

FIGS. 5 and 6 show the simulated profiles of oil saturation andtemperature after 3-year steam injection for the three cases. Note thatdue to element of symmetry, the case of the SW-SAGD with centeredinjection point only shows one half of the well length and the case ofthe SW-SAGD with two injection points shows a quarter of the welllength.

For the conventional SW-SAGD, the steam chamber extends to about ⅓ ofthe well length, leaving ⅔ of the well length not in production. Thecase with centered steam injection point results in steam chamberdevelopment over half of the well length and the case with two injectionpoints show the steam zone over almost 80% of the well length. Thus,simply moving the steam injection point to the middle of the well, andby adding more than one injection point, the steam zone can cover theentire well.

Production Simulations

In order to prove the benefit of the CPSW-SAGD and MPSW-SAGD weperformed production simulations, also using CMG-STARS. FIG. 7 comparesthe oil production rate of the three cases from above.

Surprisingly, the oil production rate is almost doubled from theconventional SW-SAGD by placing the injection point in the middle of thewell, and is further lifted by 50% when two injection points areimplemented.

The oil rate drop at 1600 days in the case with two injection points isdue to the steam chamber coalescence. With two injection points, twosteam chambers develop that are separated from each other at thebeginning. As steam injection continues, both steam chambers will growvertically and laterally. Depending on the distance between the twosteam injection points, the edges of the two steam chambers willeventually meet somewhere in the mid-point, in a phenomena called“coalescence” of the steam chamber. The sum of surface area of the twochambers is larger before coalescence than after coalescence, becauseone of the boundaries is shared after coalescence. The heating of oiland resulting oil drainage depends on the surface or contact area.Therefore, it is typical that the oil rate drops when the steam chambercoalescences.

FIG. 5 shows the comparison of the oil recovery factor, which againillustrates the significant improvement of the described invention overthe conventional SW-SAGD.

We have not yet run a simulation case with 3 injection points, but weexpect even faster oil recovery. It is predicted that the wells canthereby be longer to fully realize the benefits of three injectionpoints.

The simulated payzone was big at 20 m. However, the relative gain reallycomes from the surface area increase due to doubling size of theincipient steam chambers. Thus, even with a thinner pay zone, we stillexpect the same relative performance improvement.

The following references are incorporated by reference in their entiretyfor all purposes.

Falk, K., et al., Concentric CT for Single-Well Steam Assisted GravityDrainage, World Oil, July 1996, pp. 85-95.

McCormack, M., et al., Review of Single-Well SAGD Field OperatingExperience, Canadian Petroleum Society Publication, No. 97-191, 1997.

Moreira R. D. R., et al., IMPROVING SW-SAGD (SINGLE WELL STEAM ASSISTEDGRAVITY DRAINAGE), Proceedings of COBEM 2007 19th International Congressof Mechanical Engineering, available online atwww.abcm.org.br/pt/wp-content/anais/cobem/2007/pdf/COBEM2007-0646.pdf.

Faculdade de Engenharia Mecânica, Universidade estadual de Campinas. Sã

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U.S. Pat. No. 5,626,193 Method for recovering heavy oil from reservoirsin thin formations

1) A method of producing heavy oils from a reservoir by single wellsteam and gravity drainage (SW-SAGD), comprising: a) providing ahorizontal well below a surface of a reservoir; b) said horizontal wellhaving a toe end and a heel end and a middle therebetween; c) injectingsteam into one or more injection points between said toe end and saidheel end; and d) simultaneously producing mobilized heavy oil; e)wherein said method produces more oil at a time point than a similarSW-SAGD well with steam injection only at said toe. 2) The method ofclaim 1, wherein each injection point is separated from a productionsegment by at least two thermal packers. 3) The method of claim 1,wherein an injection point is at said middle. 4) The method of claim 1,wherein two injection points are at about ¼ and ¾ of a horizontal lengthof said well. 5) The method of claim 1, wherein injected steam includessolvent. 6) The method of claim 1, wherein said method includes apreheating phase wherein steam is injected along the entire length ofthe well. 7) The method of claim 1, wherein said method includes acyclic preheating phase comprising a steam injection period along theentire length of the well followed by a soaking period. 8) The method ofclaim 7, including two cyclic preheating phases. 9) The method of claim7, including three cyclic preheating phases. 10) The method of claim 1,wherein said method includes a pre-heating phase comprising a steaminjection in both the injection segment and the production segmentfollowed by a soaking period. 11) The method of claim 10, including twocyclic pre-heating phases. 12) The method of claim 10, including threecyclic pre-heating phases. 13) The method of claim 7, wherein saidsoaking period is 10-30 days. 14) The method of claim 7, wherein saidsoaking period is 20 days. 15) A well configuration for producing heavyoils from a reservoir by single well steam and gravity drainage(SW-SAGD), comprising: a) a horizontal well in a subsurface reservoir;b) said horizontal well having a toe end and a heel end and having atleast three segments comprising: i) at least two production segmentsbracketing at least one injection segment; ii) said production segmentsfitted for production; and iii) said injection segments fitted forinjection. 16) The well configuration of claim 15, wherein thermalpackers separate said injection segments and said production segments.17) The well configuration of claim 15, comprising two injectionsegments bracketed by production segments. 18) The well configuration ofclaim 16, wherein said two injection segments are at about ¼ and ¾ of anoverall well length. 19) The well configuration of claim 17, said atleast two injection segments fitted with coiled tubing having twoorifices to inject steam into said two injection segments. 20) The wellconfiguration of claim 15, comprising three injection segments bracketedby production segments. 21) An improved method of producing heavy oilsfrom a SW-SAGD, wherein steam is injected into a toe end of a horizontalwell to mobilize oil which is simultaneously produced at a heel end ofsaid horizontal well, the improvement comprising providing one or moreinjection points for steam between said heel end and said toe end duringa production phase, thus improving a CSOR of said horizontal well at atime period as compared to a similar well with steam injection only atsaid toe end during said production phase.